The instant invention relates to a degradable composition, method of manufacture and method of use for ball sealers, which are used for temporarily sealing casing perforations, and a fluid loss additive, which is mixed with fluids for temporarily sealing formation fissures. In particular the invention relates to wellbore stimulation treatments in the oil and gas industry.
Produced fluids (fluids are defined as liquids and gases) coming from a wellbore in the oil and gas industry are drawn from subterranean formations. The formation itself tends to restrict the flow of its own fluids, and the industry has defined a parameter which measures the tendency of fluids to flow under unequal pressure within a formation called permeability. Thus, the industry is interested in the permeability of a producing formation and employs techniques to maximize the permeability. There are several factors which affect the permeability of the formation which includes the effect of pores (the interstitial structure of the formationxe2x80x94namely voids, holes and other spaces), the effect of other fluids within the formation, and the effect of pore throats. Pore throats are essentially small pores within the formation.
After the actual drilling of a wellbore is complete, and if the well is successful, the industry performs an operation called completion. Completion is a series of involved operations and includes casing of the wellbore (running a steel tube from basically the bottom of the wellbore to the surface), cementing the casing in place within the wellbore (this operation fills voids between the steel casing and the formation strata and assures that one or more zones will not be in direct communication except through casing perforations), explosive perforation of the casing (punching holes through the steel tube and cement into the subterranean formation at the points where produced fluids are located), followed by cleaning and stimulation of the particular producing formation or formations.
Perforation involves the controlled explosive release of gases which are designed to penetrate the casing, penetrate any cement, and penetrate the subterranean formation immediately next to the casing. The penetration into the formation is dependent on the size of the charge, the type of formation (sand, sandstone, etc.), the size and thickness of the casing, and myriad other parameters; thus, the perforation extending from the casing into the formation ranges from a couple of inches to several feet. The term xe2x80x9cperforationxe2x80x9d as used in the industry generally refers to the holes punched in the casing. It is assumed that the perforation operation will xe2x80x9cpunchxe2x80x9d circular holes through the casing and cement into the formation. Most of the time this assumption is true; however, perforations can be irregular in shape.
After the perforation operation is complete, and as part of well completion the wellbore and the producing formation (or formations, in the case of multiple zones) must be cleaned and prepared for production. This series of operations are designed to remove remaining wellbore cuttings (the ground formation strata due to the drilling operation), remaining drilling fluids which are trapped behind the casing and in the production zone or zones, and stimulate the production by increasing the permeability. These operations are run from the surface and involve pumping various fluids, including acids, surfactants and other stimulation and cleaning fluids, down the wellbore into the production formation. The fluids will pass through perforations in the casing and into the formation. After a period of time, pressures are reduced so that the fluid will back-flow and draw impurities back into the wellbore and up to the surface. Sometimes the operator must pressure stimulate the producing zone (or zones) which requires pumping a fluid such as an acid, liquefied gas, a sand slurry, a viscous liquid, or another liquid into the wellbore under high pressure. The high pressure fluid flows through the casing and cement perforations and into the formation where the high pressure causes the formation to crack or fracture; hence, the name fracturing is used to describe this operation.
There is one substantial drawback in the initial cleaning and stimulation operations. The fluids will readily flow through the casing perforations and into the formation wherever the formation permeability is high. Thus, wherever the permeability is low a fracturing treatment is an economic necessity. Stimulation fluids will flow most easily into the high permeability zones. Extra pressure will be required to force the fluids into the lower permeability part of the formation. This extra pressure will in turn force additional fluids into zones which already have high permeability and could damage those zones by excess fluid leak off. In the case of acid fracturing (a high pressure operation) the possibility of damage to production formation is substantially increased. Thus, a method for diverting, controlling or directing the flow of stimulation or cleaning fluids into the formation through casing perforations is required.
After the wellbore is placed in service and as the produced fluids flow through the formation, the produced fluids draw other materials along which often precipitate out (or just drop out) of the fluid. These materials will block the pores; thus, decreasing the permeability over time.
After a period of time, the operator of the wellbore must return to the site and treat the formation again to improve the permeability and production rate. These secondary stimulation treatments are similar to the initial treatments and generally include acids and surfactants, both of which are pumped into the wellbore and into the formation. During these secondary treatment operations, the areas of the formation where the permeability has decreased should be treated. Unfortunately, the treating fluids will flow most readily into the formation with the highest permeabilityxe2x80x94namely where the fluids are not needed, which is the same problem encountered during the initial treatment. In limited cases fracturing is again used and the danger of formation damage reappears. Thus, it is desirable to control or divert fluid flow into the regions with high permeability while forcing the fluids into regions of low permeability.
The industry has developed a product and method to control and direct treatment fluids through casing perforations and into the production zone or zones. The product is called a ball sealer: in reality a series of ball sealers which are capable of plugging the casing perforations. The ball sealers are slightly larger than the casing perforation and are capable of shutting off fluid flow through the casing perforation if and when they fall in front of a perforation. (The art is placing the sealers in the wellbore so that they will seal a perforation at the right time.) The associated method involves pumping the ball sealers into the wellbore along with the treatment fluids in an orderly manner so that they plug the offending perforation at the right time.
The standard method of use requires that the ball sealers be staged in the stimulation fluid as it is pumped into the wellbore. For example, assume that a simulation treatment requires 24 barrels (1,000 gallons) of fluid, and it is known that there are 24 perforations in the wellbore; thus 48 balls will be required. (The operator generally doubles the number of perforations to determine the number of balls.) In this example, the operator would release one ball for each one-half barrel pumped into the wellbore. This will help assure that each perforation is treated with an adequate amount of stimulation fluid before the next ball contacts the next perforation sealing it prior to increased fluid pressure breaking down (opening up) the next unsealed perforation and treating the formation associated with that perforation. The sequence of seal a perforation, treat the next, seal that perforation, treat the next, etc. continues until all the perforations have been ideally treated. At the surface, the operator will note a slight increase in pressure as one perforation is sealed and until the next formation opens up under pressure with an associated pressure decrease. The actual order of perforation treatment will not be from bottom to top, but will be associated with the order in which a given formation associated with a given perforation opens up. Ideally, at the end of the operation, all perforations seal and a sharp pressure increase is seen at the surface: this phenomena is called xe2x80x9cballing outxe2x80x9d and indicates that all perforations have been treated.
Once the initial or secondary operations are complete, the ball sealers fall away from the perforations (due to flow from the formation into the wellbore) and generally remain in the wellbore where they become a nuisance and present operational problems. Most wellbores contain a xe2x80x98rat holexe2x80x99 which is an extension of the wellbore below the lower casing perforation about 20 plus feet in depth. (In some wellbores this rat hole can become filled with debris and no longer exists.) The balls fall into the rat hole, where, under some circumstances one may be picked up by the motion of the produced fluid and carried to surface. At the surface a renegade ball can plug the surface production valves creating a safety hazard. Some operators will place xe2x80x9cball catchersxe2x80x9d at the surface to avoid this problem. Often the wellbore operator must reenter the hole with drilling tools and the excess balls surround the drilling pipe or downhole tools jamming the pipe or tools in the wellbore. This results in an expensive xe2x80x9cfishingxe2x80x9d operation to retrieve the jammed tools.
Ball sealers are but one product used in treating a wellbore and the associated production zones. As previously mentioned a stimulation fluid is pumped into the wellbore under pressure which penetrates the formation and hydraulically fractures the formation. Hydraulic fracturing is well understood in the industry and is used with old wells and new wells to increase the production rate by changing radial flow to linear flow and bypassing near wellbore damage. The process is not simple and does not involve a simple fracturing liquid.
A typical fracture treatment fluid would comprise a thickened fluid such as an aqueous gel, emulsion, foamed fluid, gelled alcohol, or an oil based fluid. This xe2x80x9cbasexe2x80x9d increases the hydraulic effect and generally supports additional materials called xe2x80x9cproppantsxe2x80x9d. Proppants are designed to remain in the fractured formation and xe2x80x9cpropxe2x80x9d the fractures open. A properly designed proppant is pumped into the fracture by the fracturing fluid to form a highly porous matrix through which the formation fluid may readily pass to the wellbore.
Another problem will occur in most fracturing operations, which causes considerable grief to the operator. A producing formation occurs in more or less horizontal layers which undulate. These layers can range from several feet to several hundred feet thick. As the fracturing operation proceeds, the fractures may propagate vertically out of the target zone. This allows the fracturing fluid to move into a non-producing formation located above and/or below the producing formation. Usually the non-producing formations are shale layers or permeable zones with little gas or oil content. Total fluid loss is defined as the amount of fracturing fluid lost to the total area of exposed formation of the created fracture and is well known and understood in the industry. Fluid loss must be controlled; otherwise, the fracture width will not be sufficient to allow the proppants to enter the fracture and keep it propped open (or sand out can occur).
Therefore, additional materials are placed in the fracturing liquid to limit fluid loss. These materials are termed xe2x80x9cfluid loss (fluid-loss) additivesxe2x80x9d and are well known in the industry. Unfortunately, a fluid loss additive is designed to slow fluid lost to the formation by bridging over pores, fissures, etceteras, which reduces the permeability of the formation to the fluid. The very opposite of the end result that is desired in a hydraulic fracturing operation. These fluid loss additives are carefully formulated to break down within the formation after the fracturing operation is complete. Some of the breakdown occurs because the additive goes back into solution or additional chemicals are pumped into the formation to make the additives break down. This xe2x80x9cafter-processxe2x80x9d is termed cleanup in the industry. The current additives produce xe2x80x9ccleanupxe2x80x9d that varies greatly from well to well in the field.
As stated above, ball sealers and the method of use have been known to and utilized by the industry for many years. The early ball sealers were usually made from a solid core with an outer coating made from rubber or a similar polymer coating. The core and coating were chosen so that the ball would be slightly buoyant in the stimulation fluidxe2x80x94be it acid or surfactant based. These balls were then added to the stimulation fluid at appropriate times during the stimulation operation and suspend themselves in the stimulation fluid. The balls are then carried down into the wellbore and plug off perforations which are in communication with high permeability strata; thus, diverting the stimulation fluid to perforations in communication with low permeability strata. The rubber/polymer coated ball sealers would remain in the wellbore and caused problems such as reported in the previous section.
The problems associated with the ball sealers remaining in wellbore have been addressed in a number of ways. One of the ways was to add a ball catcher at the surface; however, this solution did not address the problems caused by the balls when reentering a wellbore for certain drilling operations. U.S. Pat. No. 4,716,964 to Erbstoesser et al. discloses a method for using biodegradable ball sealers in a wellbore. The method patent is a continuation of a division of its U.S. Pat. No. 4,387,769 which disclosed a method for reducing the permeability of the actual formation during stimulation operations. The biodegradable ball sealer is disclosed in U.S. Pat. No. 4,526,695 which discloses and claims a biodegradable ball sealer. Erbstoesser discloses and claims a solid polymer ball sealer with the polymer being substantially insoluble in a stimulation fluid and degradable in the presence of water at elevated temperatures to oligomers which themselves are at least partially soluble in oil or water. Ball sealers following the Erbstoesser disclosure do not appear to be available on the market. The actual reason for lack of availability is not known; however, it is believed that the sealers using the Erbstoesser technology tend to break down too early or they cannot hold up under the stimulation pressures experienced in a wellbore. For example, if a ball sealer is extruded through a casing perforation into the formation, and /or cement seal lying immediately next to the casing, and if the compound will not readily breakdown in the wellbore fluid, that perforation will have problems. Erbstoesser (see U.S. Pat. No. 4,716,964) hints that such problems may occur with pressure differentials of 200 PSI and at temperatures in the range of 150 to 160 degrees Fahrenheit.
Kendrick et al. in U.S. Pat. No. 5,253,709 attempted to address the problem caused by irregular shaped perforations. Kendrick proposed a hard center ball with a deformable outer shell which would deform to the irregular shape of a casing perforation. The inner core is manufactured from binders and wax that is to melt at downhole temperatures; whereas the outer covering is a rubber. The ball would then pop loose from the casing perforation after a period of time; however, nothing is mentioned as to a degradable outer surface, and it would appear that the balls would remain intact in the wellbore.
There are other problems associated with the current generation of ball sealers. One of these problems is apparent in low pressure wells. After the well is treated using ball sealers, the formation pressure is insufficient to push the balls out of the casing perforations due to simple hydrostatic fluid pressure caused by the fluid head in the wellbore. If the balls do not readily break down a mechanical scrapper must be run down the wellbore or the well will not produce and the stimulation operation would be wasted.
Thus, there remains a need for an improved ball sealer (1) that is capable of diverting fluid flow from casing perforations which are in communication with highly permeable strata to perforations which are in communication with low permeability strata, (2) that will readily degrade in the stimulation fluid at the elevated temperatures found in wellbores but only after the stimulation process is complete, (3) that will degrade by becoming soluble in the fluids found in wellbores, (4) that is capable of deformation to conform to an irregular-shaped casing perforation, and (5) retain its strength and not extrude through a perforation casing while the stimulation process is underway.
In the area of compounds used in applications within and without the oil industry, U.S. Pat. No. 4,064,055 to Carney discloses an Aqueous Drilling Fluids and Additives Therefore which teaches a friction reducer using some of the compounds disclosed in this invention. U.S. Pat. No. 3,971,852 to Brenner discloses a Process of Encapsulating an Oil and Product Produced Thereby which teaches the process of encapsulating oil (perfumes) in a solid matrix.
In the area of compounds used in fluid loss additives, U.S. Pat. No. 5,032,297 to Williamson et al. discloses an Enzymatically Degradable Fluid Loss Additive which teaches the addition of an enzyme to the standard fluid-loss inhibitors comprising a mixture of natural and modified starches which are broken down by the enzyme; however, the enzyme does not affect the guar (a natural polymer) used in the fracturing fluid. One of the earlier patents, U.S. Pat. No. 3,319,716 to Dill, discloses a Fluid Loss Additive for Well Fluids, Composition and Process. This patent discusses the use of ground oil soluble resins in guar and gums; however, it does not discuss the concept of biodegradable additives.
U.S. Pat. No. 5,246,602 to Forrest discloses a Method and Composition Fracturing Subterranean Formations, which teaches the addition of finely ground peanut hulls within a certain mesh distribution to the fracturing fluid to act as an additive.
U.S. Pat. No. 5,301,751 to Githens et al. discloses a Method for Using Soap as a Soluble Fluid Loss Additive in the Hydraulic Fracturing Treatment of Oil and Gas Wells, which teaches the use of biodegradable soap to act as a loss-inhibitor and cleanup agent in conjunction with normal polymers and other agents. U.S. Pat. No. 5,354,786 to Lau discloses a Fluid Loss Control Composition which teaches a polymer composition containing halogen-substituted organic acids or salts which hydrolyze after the fracture operation is complete. The hydrolyses reaction in turn releases hydrogen-halogen acids which in turn break down the polymer, thus, cleaning up the formation.
U.S. Pat. No. 5,415,228 to Price et al. discloses Fluid Loss Control Additives for Use with Gravel Pack Placement Fluids which teaches the use of carefully distributed soluble particles (calcium carbonate) to achieve fluid loss control. U.S. Pat. No. 5,439,057 to Weaver et al. discloses a Method for Controlling Fluid Loss in High Permeability Formations which teaches a cross linked polymer gel broken into discrete particles and dispersed in the fracturing fluid. The resulting fluid interacts with the formation and fracturing fluid constituents to form the required fluid-loss control filter cake.
Thus there still remains a fluid-loss additive that is degradable within the formation using natural fluids occurring in the formation or in the fracturing fluid and which produces substantially improved xe2x80x9cclean-upxe2x80x9d over the existing art. Further, there is real need for a fluid loss additive which itself does not permanently damage the formation resulting in reduced permeability and thus lower production rates from the well.
The present invention relates generally to a composition of matter and method of manufacture used for degradable ball sealers and/or a fluid-loss additive to be utilized in the oil and gas industry. The present invention comprises an injection molded ball sealer and/or fluid loss additive both of which are comprised of a mixture of thermosetting adhesives and fillers which are soluble in water, surfactants and other aqueous based fluids found in most wellbores over a controlled period of time. For purposes of explanation, but not as a limitation, the filler material consists of glycerin, wintergreen oil, oxyzolidine, oil, and water.
The ball sealer of the present invention is manufactured in a two step process. First a slurry comprising the preferred composition consisting of collagen and fillers is mixed and allowed to set up. The resulting composition is ground and sent to an injection molding device, using standard and known techniques, to be formed into balls having a diameter that is somewhat greater than the wellbore perforation. (Various diameters are produced but not usually exceeding 1.5 inches in diameter. This must not be read as a limitation, for if the balls are used to temporarily seal a production tubing, then the balls will have a greater diameter.) The ensuing balls will have a specific gravity in the range of 1.1 to 1.2. The specific gravity must not be read as a limitation for the specific gravity may be adjusted to fall in the range 0.5 to 2 depending on the mix of the composition used to manufacture the balls. Thus, the resulting ball comprises a round, solid, smooth surfaced seal ball with suitable characteristics that allow it to soften slightly on its surface in the presence of the stimulating fluid; thus, assuring a solid contact with the casing perforation, through controlled surface deformation, throughout the casing perforation. The core of the ball retains its strength until the stimulation operation is complete. Sometime after the operation is complete and certainly within a reasonable period of time, the balls will degrade and go into solution.
The fluid loss additive is manufactured using one of two processes. Ball sealers which are improperly shaped (out of specification) are ground up to form particles in the distribution range of xe2x88x9280 mesh to +270 mesh. Alternatively, the compound used for manufacture of ball sealers is poured into thin sheets (conveniently sized for handling) and dried in an oven or kiln. (This drying process produces a similar effect as does injection molding and drying of the ball sealers.) The particles are mixed in the ratio of 20 pounds mass to 1000 gallons of fracturing fluid, although this proportion can and will be adjusted by those skilled in the art of fracturing. Standard techniques are then used to fracture the formation with the additive forming the usual filter cake against the fracture face. After the fracturing operation is complete, and just like the ball sealers, described above, the fluid loss additive breaks down within the formation fluid. This then allows the filter cake to fall away from and disperse from the fracture face which results in a better than usual initial cleanup. Standard cleanup techniques are then utilized with fracturing fluids containing ammonium persulphate, or equivalent, to achieve cleanup results which are substantially better than the current art allows.
Thus, the first objects of this invention to provide a degradable ball sealer which will properly and completely seal casing perforations have been met. The ball sealers will break down in an aqueous fluid and therefore they can be used in a low pressure well, and the ball sealers could be used to temporarily plug the perforations during certain wellbore operations in which a wellbore fluid (e.g., mud) which is harmful to the producing formation is used. Thus, the second objects of this invention, which stem from the properties of the composition, to provide a degradable fluid loss additive have been met. The fluid loss additive will break down in an aqueous solution leaving little damage to the formation. These and other objects and advantages of the present invention will become apparent to those skilled in the art after considering the detailed specification in which the preferred embodiments are described. In particular the use of the balls to seal production tubing for pressure testing.